Basal Planer Gravity Drainage

ABSTRACT

Systems and methods are provided for producing hydrocarbons from reservoirs. A provided method includes drilling a first horizontal well substantially proximate to a base of a reservoir and drilling a second horizontal well at a horizontal offset from the first horizontal well. Fluid communication is established between the first horizontal well and the second horizontal well through cyclic production processes. A mobilizing fluid is injected through the second horizontal well and fluids are produced from the first horizontal well.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of Canadian patent application number 2,744,749 filed on Jun. 30, 2011 entitled BASAL PLANER GRAVITY DRAINAGE, the entirety of which is incorporated herein.

FIELD

The present techniques relate to the use of steamflooding to recover hydrocarbons. Specifically, techniques are disclosed for creating fluid communications between spaced horizontal wells at different levels in a reservoir.

BACKGROUND

This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present techniques. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present techniques. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.

Modern society is greatly dependant on the use of hydrocarbons for fuels and chemical feedstocks. However, easily harvested sources of hydrocarbon are dwindling, leaving less accessible sources to satisfy future energy needs. As the costs of hydrocarbons increase, these less accessible sources become more economically attractive.

For example, the harvesting of oil sands to remove hydrocarbons has become more extensive as it has become more economical. The hydrocarbons harvested from these reservoirs may have relatively high viscosities, for example, ranging from 8 API, or lower, up to 20 API, or higher. Accordingly, the hydrocarbons may include heavy oils, bitumen, or other carbonaceous materials, collectively referred to herein as “heavy oil,” which are difficult to recover using standard techniques.

Several methods have been developed to remove hydrocarbons from oil sands. For example, strip or surface mining may be performed to access the oil sands, which can then be treated with hot water or steam to extract the oil. However, deeper formations may not be accessible using a strip mining approach. For these formations, a well can be drilled to the reservoir and steam, hot air, solvents, or combinations thereof, can be injected to release the hydrocarbons. The released hydrocarbons may then be collected by the injection well or by other wells and brought to the surface.

A number of techniques have been developed for harvesting heavy oil from subsurface formations using thermal recovery techniques. Thermal recovery operations are used around the world to recover liquid hydrocarbons from both sandstone and carbonate reservoirs. These operations include a suite of in-situ recovery techniques that may be based on steam injection, solvent injection, or both. These techniques may include cyclic steam stimulation (CSS), steamflooding, and steam assisted gravity drainage (SAGD), as well as their corresponding solvent based techniques.

For example, CSS techniques include a number of enhanced recovery methods for harvesting heavy oil from formations that use steam heat to lower the viscosity of the heavy oil. The CSS process may raise the steam injection pressure above the formation fracturing pressure to create fractures within the formation and enhance the surface area access of the steam to the heavy oil, although CSS may also be practiced at pressures that do not fracture the formation. The steam raises the temperature of the heavy oil during a heat soak phase, lowering the viscosity of the heavy oil. The injection well may then be used to produce heavy oil from the formation. The cycle is often repeated until the cost of injecting steam becomes uneconomical, for instance if the cost is higher than the money made from producing the heavy oil. However, successive steam injection cycles reenter earlier created fractures and, thus, the process becomes less efficient over time. CSS is generally practiced in vertical wells, but systems are operational in horizontal wells.

Solvents may be used in combination with steam in CSS processes, such as in mixtures with the steam or in alternate injections between steam injections. The liquid hydrocarbons may be directly mixed and flashed into the injected steam lines or injected into the CSS wellbores and further transported as vapours to contact heavy oil surrounding steamed areas between adjacent wells. The injected hydrocarbons may be produced as a solution in the heavy oil phase. The loading of the liquid hydrocarbons injected with the steam can be chosen based on pressure drawdown and fluid removal from the reservoir using lift equipment in place for the CSS.

As a field ages, the use of CSS may gradually be replaced with non-cyclic techniques, for example, in which steam is continuously injected into a first well, and fluids are continuously produced from a second well. These techniques may generally be termed steamflooding, and are generally based on vertical wells. However, steam and injected fluids have a tendency to override the hydrocarbons in the formation, and directly travel from injector to producer, lowering the potential recovery.

Another group of techniques is based on a continuous injection of steam through a first well to lower the viscosity of heavy oils and a continuous production of the heavy oil from a lower-lying second well. Such techniques may be termed “steam assisted gravity drainage” or SAGD.

In SAGD, two horizontal wells are completed into the reservoir. The two wells are first drilled vertically to different depths within the reservoir. Thereafter, using directional drilling technology, the two wells are extended in the horizontal direction that result in two horizontal wells, vertically spaced from, but otherwise vertically aligned with the other. Ideally, the production well is located above the base of the reservoir but as close as practical to the bottom of the reservoir, and the injection well is located vertically 3 to 10 metres (10 to 30 feet) above the horizontal well used for production.

The upper horizontal well is utilized as an injection well and is supplied with steam from the surface. The steam rises from the injection well, permeating the reservoir to form a vapour chamber that grows over time towards the top of the reservoir, thereby increasing the temperature within the reservoir. The steam, and its condensate, raise the temperature of the reservoir and consequently reduce the viscosity of the heavy oil in the reservoir. The heavy oil and condensed steam will then drain downward through the reservoir under the action of gravity and may flow into the lower production well, whereby these liquids can be pumped to the surface. At the surface, the liquids flow into processing facilities where the condensed steam and heavy oil are separated, and the heavy oil may be diluted with appropriate light hydrocarbons for transport by pipeline.

The techniques discussed above may leave a substantial remainder of hydrocarbons in the reservoir. For example, each SAGD well pair may harvest hydrocarbons from a limited area of a reservoir, requiring a substantial number of wells. Infill wells are generally designed in a similar fashion to the lower, drainage wells in SAGD having a horizontal run placed between two SAGD pairs. Further, current steamflooding techniques may allow steam to override the hydrocarbons

SUMMARY

An embodiment of the present techniques provides a method for producing hydrocarbons from a reservoir. The method includes drilling a first horizontal well substantially proximate to a base of a reservoir and drilling a second horizontal well at a horizontal offset from the first horizontal well. Fluid communication is established between the first horizontal well and the second horizontal well through cyclic production processes. A mobilizing fluid is injected through the second horizontal well and fluids are produced from the first horizontal well.

Another embodiment provides a system for harvesting resources in a reservoir. The system includes a first horizontal well substantially proximate to the base of the reservoir and a second horizontal well at a horizontal offset from the first horizontal well, wherein the second horizontal well is vertically offset from the first horizontal well. A cyclic production system is configured to establish fluid communication between the wells. A continuous injection and production system is configured to inject a mobilizing fluid into the second horizontal well and produce a fluid from the first horizontal well.

Another embodiment provides a method for producing hydrocarbons. The method includes producing fluids from a number of production wells in a reservoir, wherein each of the production wells are located substantially proximate to the base of the reservoir. Mobilizing fluids are injected into the reservoir through a number of injection wells, wherein each of the plurality of injection wells is adjacent to one of the plurality of production wells. Further, each of the injection wells is laterally offset from each of the adjacent production wells, and each of the injection wells is drilled at a higher level than each of the adjacent production wells. A hydrocarbon stream is separated from the fluids produced from the plurality of production wells.

DESCRIPTION OF THE DRAWINGS

The advantages of the present techniques are better understood by referring to the following detailed description and the attached drawings, in which:

FIG. 1 is a drawing of a steamflood process using basal planar gravity drainage;

FIGS. 2(A), (B), and (C) are perspective views of a cyclic production process showing the establishment of fluid communications between adjoining wells;

FIG. 3 is a cross sectional view of a cyclic production process showing the establishment of fluid communications between adjoining wells;

FIG. 4 is a cross-section of a portion of a reservoir, showing two horizontal wells through the reservoir;

FIG. 5 is a plot showing an increase in total production that can be obtained using the present techniques;

FIGS. 6 is a plot showing an increase in efficiency that can be obtained using the present techniques; and

FIG. 7 is process flow diagram of a method for using basal planar gravity drainage to produce hydrocarbons.

DETAILED DESCRIPTION

In the following detailed description section, specific embodiments of the present techniques are described. However, to the extent that the following description is specific to a particular embodiment or a particular use of the present techniques, this is intended to be for exemplary purposes only and simply provides a description of the exemplary embodiments. Accordingly, the techniques are not limited to the specific embodiments described below, but rather, include all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.

At the outset, for ease of reference, certain terms used in this application and their meanings as used in this context are set forth. To the extent a term used herein is not defined below, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. Further, the present techniques are not limited by the usage of the terms shown below, as all equivalents, synonyms, new developments, and terms or techniques that serve the same or a similar purpose are considered to be within the scope of the present claims.

As used herein, the term a “base” of a reservoir indicates a lower boundary of the resources in a reservoir that are practically recoverable, by a gravity-assisted drainage technique, for example, using an injected mobilizing fluid, such as steam, solvents, hot water, gas, and the like. The base may be considered a lower boundary of a pay zone, e.g., the zone from which hydrocarbons may generally be removed by gravity drainage. The lower boundary may be an impermeable rock layer, including, for example, granite, limestone, sandstone, shale, and the like. The lower boundary may also include layers that, while not completely impermeable, impede the formation of fluid communication between a well on one side and a well on the other side. Such layers may include broken shale, mud, silt, and the like. The resources within the reservoir may extend below the base, but the resources below the base may not be recoverable with gravity assisted techniques.

“Bitumen” is a naturally occurring heavy oil material. Generally, it is the hydrocarbon component found in oil sands. Bitumen can vary in composition depending upon the degree of loss of more volatile components. It can vary from a very viscous, tar-like, semi-solid material to solid forms. The hydrocarbon types found in bitumen can include aliphatics, aromatics, resins, and asphaltenes. A typical bitumen might be composed of:

19 wt. % aliphatics (which can range from 5 wt. %-30 wt. %, or higher);

19 wt. % asphaltenes (which can range from 5 wt. %-30 wt. %, or higher);

30 wt. % aromatics (which can range from 15 wt. %-50 wt. %, or higher);

32 wt. % resins (which can range from 15 wt. %-50 wt. %, or higher); and

some amount of sulphur (which can range in excess of 7 wt. %).

In addition bitumen can contain some water and nitrogen compounds ranging from less than 0.4 wt. % to in excess of 0.7 wt. %. As used herein, the term “heavy oil” includes bitumen, as well as lighter materials that may be found in a sand or carbonate reservoir.

As used herein, two locations in a reservoir are in “fluid communication” when a preferential path for fluid flow exists between the locations. Fluid communication can be manifested as a rapid pressure change at one well in response to a pressure, fluid injection or fluid withdrawal at another well. Fluid communication may also be manifested as temperature change at the production well or the arrival at the production well of fluids that are known to have been injected at another well. For example, the establishment of fluid communication between a well and a latterly or vertically offset injection well may allow steam or solvent to flow rapidly and with limited pressure drop from the injection well to the production well where it can be collected and produced. As used herein, a fluid includes a gas or a liquid and may include, for example, a produced hydrocarbon, an injected mobilizing fluid, or water, among other materials.

As used herein, a “cyclic recovery process” uses an intermittent injection of injected mobilizing fluid selected to lower the viscosity of heavy oil in a hydrocarbon reservoir. The injected mobilizing fluid may include steam, solvents, gas, water, or any combinations thereof. After a soak period, intended to allow the injected material to interact with the heavy oil in the reservoir, the material in the reservoir, including the mobilized heavy oil and some portion of the mobilizing agent may be harvested from the reservoir. Cyclic recovery processes use multiple recovery mechanisms, in addition to gravity drainage, early in the life of the process. The significance of these additional recovery mechanisms, for example dilation and compaction, solution gas drive, water flashing, and the like, declines as the recovery process matures. Practically speaking, gravity drainage is the dominant recovery mechanism in most mature thermal, thermal-solvent and solvent based recovery processes used to develop heavy oil and bitumen deposits, such as steam assisted gravity drainage (SAGD). For this reason the approaches disclosed here are equally applicable to all recovery processes in which at the current stage of depletion gravity drainage is the dominant recovery mechanism.

“Facility” as used in this description is a tangible piece of physical equipment through which hydrocarbon fluids are either produced from a reservoir or injected into a reservoir, or equipment which can be used to control production or completion operations. In its broadest sense, the term facility is applied to any equipment that may be present along the flow path between a reservoir and its delivery outlets. Facilities may comprise production wells, injection wells, well tubulars, wellhead equipment, gathering lines, manifolds, pumps, compressors, separators, surface flow lines, steam generation plants, processing plants, and delivery outlets. In some instances, the term “surface facility” is used to distinguish those facilities other than wells.

As used herein, “heavy oil” includes both oils that are classified by the American Petroleum Institute (API) as heavy oils and extra heavy oils, which are also known as bitumen. In general, a heavy oil has an API gravity between 22.3° (density of 920 kg/m³ or 0.920 g/cm³) and 10.0° (density of 1,000 kg/m³ or 1 g/cm³). An extra heavy oil, or bitumen, in general, has an API gravity of less than 10.0° (density greater than 1,000 kg/m³ or greater than 1 g/cm³). For example, a common source of heavy oil includes oil sand or bituminous sand, which is a combination of clay, sand, water, and heavy oil. The thermal recovery of heavy oils is based on the viscosity decrease of fluids with increasing temperature. Solvent-based recovery processes are based on reducing the liquid viscosity by mixing heavy oil with a solvent. Once the viscosity is reduced, the movement or drive of the fluids may be forced by steam or hot water flooding, and gravity drainage becomes possible. The reduced viscosity makes the drainage quicker and therefore directly contributes to the recovery rate.

As used herein, a “horizontal well” generally refers to a well bore with a section having a centerline which departs from vertical by at least about 65°. This nearly horizontal section is often used for harvesting hydrocarbons in a reservoir. Generally, the nearly horizontal section of a well bore that is used for gravity production of heavy oils extends for several hundred meters in a reservoir from the “heel” to the “toe.” The heel is closest to the portion of the well bore that leads to the surface, while the toe is farthest from the portion of the well bore that leads to the surface. In practice, the horizontal well will often be drilled such that it conforms to the base of the reservoir so that the toe may be shallower or deeper than the heel of the well.

A “hydrocarbon” is an organic compound that primarily includes the elements hydrogen and carbon, although nitrogen, sulphur, oxygen, metals, or any number of other elements may be present in small amounts. As used herein, hydrocarbons generally refer to components found in heavy oil and oil sands.

A non-condensable gas is a gas that is in the gas phase under the temperature and pressure conditions found in an oil-sands reservoir. Such gases can include carbon dioxide (CO₂), methane (CH₄), and nitrogen (N₂), among others.

“Permeability” is the capacity of a rock or sand to transmit fluids through the interconnected pore spaces. The customary unit of measurement is the millidarcy. Relative permeability refers to the fractional permeability of the absolute permeability for a specific phase, such as oil, water or gas.

As used herein, a “reservoir” is a subsurface rock or sand formation from which a production fluid, or resource, can be harvested. The rock formation may include sand, sandstone, granite, silica, carbonates, clays, shales and organic matter, such as oil, gas, or coal, among others. Reservoirs can vary in thickness from less than one foot (0.3048 m) to hundreds of feet (hundreds of m). The common feature of a reservoir is that it has pore space within the rock that may be impregnated with a heavy oil.

As discussed above, “steam assisted gravity drainage” (SAGD), is a thermal recovery process in which steam, or combinations of steam and solvents, is injected into a first well to lower a viscosity of a heavy oil, and fluids are recovered from a second well. Both wells are generally horizontal in the formation and the first well lies above the second well. Accordingly, the reduced viscosity heavy oil flows down to the second well under the force of gravity, although pressure differential may provide some driving force in various applications.

“Substantial” when used in reference to a quantity or amount of a material, or a specific characteristic thereof, refers to an amount that is sufficient to provide an effect that the material or characteristic was intended to provide. The exact degree of deviation allowable may in some cases depend on the specific context.

As used herein, “thermal recovery processes” include any type of hydrocarbon recovery process that uses a heat source to enhance the recovery, for example, by lowering the viscosity of a hydrocarbon. These processes may use injected mobilizing fluids, such as hot water, wet steam, dry steam, or solvents alone, or in any combinations, to lower the viscosity of the hydrocarbon. Such processes may include subsurface processes, such as cyclic steam stimulation (CSS), cyclic solvent stimulation, steamflooding, solvent injection, and SAGD, among others, and processes that use surface processing for the recovery, such as sub-surface mining and surface mining. Any of the processes referred to herein, such as SAGD may be used in concert with solvents.

A “wellbore” is a hole in the subsurface made by drilling and inserting a conduit into the subsurface. A wellbore may have a substantially circular cross section or any other cross-sectional shape, such as an oval, a square, a rectangle, a triangle, or other regular or irregular shapes. As used herein, the term “well,” when referring to an opening in the formation, may be used interchangeably with the term “wellbore.” Further, multiple pipes may be inserted into a single wellbore, for example, as a liner configured to allow flow from an outer chamber to an inner chamber.

Overview

Current techniques for harvesting heavy oils may require a significant number of wells to produce hydrocarbons over a large area of a reservoir. As the costs associated with these wells can be very high, the techniques may become prohibitively expensive as a reservoir ages. Further, current techniques may bypass significant amounts of hydrocarbons as the reservoir ages.

In an embodiment, a basal planar gravity drainage process is implemented by drilling at least two horizontal wells through the reservoir. A first horizontal well is drilled at or close to the base of the reservoir. A second horizontal well is laterally offset and may be vertically offset from the first well, for example, with an axis that is around 50 to 200 metres laterally away from the axis of the first well and may be about three metres, or more, shallower than the first well. Both wells are initially used to produce from the reservoir using cyclic production techniques, such as injecting a mobilizing fluid, letting the mobilizing fluid soak in the reservoir, and then producing the mobilizing fluid and hydrocarbons from the wells. The mobilizing fluid may be steam, water, solvents, or mixtures of both.

Over time, as production cycles are completed, the first horizontal well and the second horizontal well will achieve fluid communication, allowing fluids injected through one well to pass to the other well. After fluid communication is achieved, a continuous production process may be implemented in which the second, or higher, horizontal well may be used as an injection well, and the first, or lower, horizontal well may be used as a production. As for the cyclic production process, the continuous production process may use steam, solvents, water, or mixtures, as mobilizing agents.

The basal planar gravity drainage process may increase the amount of hydrocarbons that can be harvested from a reservoir. The basal planar gravity drainage process may also increase the efficiency of steam or solvent usage in the recovery process.

FIG. 1 is a drawing of a hydrocarbon recovery process 100 in accordance with embodiments. In the hydrocarbon recovery process 100, a reservoir 102 is accessed by a first set 104 and a second set 106 of horizontal wells. As described herein, the wells can have a lateral spacing 108 of about 50 to 200 metres between each of the wells. The first set 104 may be drilled substantially proximate to a base 110 of the reservoir 102. The second set 106 of horizontal wells may be drilled at a vertical spacing 112 of about three metres, or more, above the first set 104. Although only two wells of each type are shown in the hydrocarbon recovery process 100, any number may be used, for example, from one well of each type to several hundred wells of each type, depending on the size of the reservoir 102. The first set 104 of horizontal wells may be coupled together by lines 114 at the surface. Similarly, the second set 106 of horizontal wells may be coupled together by lines 118 at the surface. One or more surface facilities 120 produce steam or solvent streams that can be injected into the reservoir through the sets of wells 104 or 106 and produce fluids from the sets of wells 104 or 106. The produced fluids may be separated at the surface facility 120 to produce a hydrocarbon stream 122, which can then be sent on for further processing.

After the sets of wells 104 and 106 are drilled, a cyclic production process, such as cyclic steam stimulation, may be used on both sets 104 and 106 of horizontal wells in concert. During this period, the surface lines 114 and 118 may be tied together so that the sets of wells 104 and 106 are used in concert. The cyclic production process is repeated until fluid communication between the first set 104 and the second set 106 of wells is detected. At that point, the second set 106 of wells may be used for continuous injection of a mobilizing fluid, while the first set 104 may be used for production, for example, of hydrocarbons and the mobilizing fluid.

Establishing Fluid Communication

FIGS. 2(A), (B), and (C) are 3D seismic views of a cyclic production process 200 showing the establishment of fluid communications between adjoining wells. In FIG. 2, the particular cyclic production process used was cyclic steam stimulation (CSS), although any cyclic production technique could be used in techniques described herein. FIG. 2(A) is an initial view showing accessed areas 202, for example, areas that may be in heated and in fluid communication with horizontal wells 204 after one cycle of cyclic steam injection and production has been performed from the reservoir 206. The accessed areas 202 may be termed the steam invaded region. The darker, shaded areas indicate regions 208 are not yet in fluid communication with the wells 204. As can be seen, the wells 204 are not substantially in fluid communication with each other at this point in the process, as indicated by the lack of overlap of the accessed areas 202 across adjacent wells 204.

After a second cycle of steam injection and production, heated features extend out to at least about 25 m from each well. In this example, the wells are about 170 metres apart and fluid communication has not been completely established. However, if the wells had been placed about 50 to 75 metres apart, basal connections would have been established at this point. Thus, after two cycles of CSS the shown in FIG. 2(B), the accessed area 202 has substantially increased in size, and is overlapping a number of adjacent wells 204, for example, as indicated by reference number 210.

After a third year of cyclic production, as shown in FIG. 2(C), the accessed region 202 has placed all adjacent wells 204 in fluid communication, allowing fluid flow from any well to an adjacent well 204. Creating uniform connections along the wells may present a challenge. For example, reference number 212 identifies a region where the fluid communication is not extensive, indicating that further cycles may be useful. However, the fluid communication may be extensive enough to begin continuous steamflooding. The wells shown in FIGS. 2(A), (B) and (C) were completed with specially designed completion which facilitated uniform steam distribution, such as limited entry perforations (LEPs) which may be used in concert with a wire screen.

FIGS. 3(A), (B), and (C) are cross sectional views 300 of the cyclic production processes of FIGS. 2(A), (B), and (C), respectively, showing the establishment of fluid communications between adjoining wells 204. In FIG. 3, like numbers are as discussed above. In this figure, not every well 204 is labelled in order to simplify the diagram. The center 302 of the production zone 304 around each well 204 is at a lateral spacing 108 of about 170 metres apart in this example. The increase in the accessed area 202 (FIG. 2) after each year of cyclic production is shown as the increase in size of the production zones 304 around each well 204. Further, other layers 306 may develop accessed zones 308, which can contribute to fluid communication between wells. If the lateral spacing 108 between were closer, fluid communications between wells 204 would be established more quickly. For example, if the spacing around the production zones 304 was at 100 metres, as indicated by reference number 310, the wells 204 could start to interact after only two years of cyclic production. The wells 204 could be converted to alternating injectors and producers, as discussed with respect to FIG. 4. In some embodiments, the lateral well spacing 108 will be about 50 metres. The lateral well spacing 108 may range from about 20 metres to about 200 metres.

Changing to Continuous Production

FIG. 4 is a cross-section of a portion 400 of a reservoir 102, showing two horizontal wells 104 and 106 in the reservoir 102 used in a continuous production process, e.g., after fluid communication is established by a cyclic production process. A first horizontal well 104 is drilled near a base of the reservoir 102. A second horizontal well 106 is drilled at a lateral offset 108 and at a shallower level, i.e., with a positive vertical offset 112. In an embodiment, the vertical offset 112 is greater than about three metres. The second horizontal well 106 may be used as an injection well to inject a mobilizing fluid to move hydrocarbons in the reservoir 102 towards the first horizontal well 402, as indicated by arrow 402.

During the injection, steam and other gases rise, as indicated by arrow 404, forming a steam or production chamber 406. Liquids, including mobilized hydrocarbons, condensate, solvents, and the like, fall, as indicated by arrow 408. These liquids drain to the first horizontal well 104, as indicated by arrow 402, which is used as a production well to remove the fluids from the production chamber 410. Unlike a typical steam assisted gravity drainage (SAGD) process, which has no lateral spacing between the injection and production well, the production chamber 406, at or near the base of the reservoir, is formed by the offset of the two horizontal wells 102 and 104. The production chamber 406 may increase the total amount of hydrocarbons that can be produced from the reservoir in a given period of time, versus a vertical SAGD steam chamber, and may increase the efficiency of the injected mobilizing fluid. This is discussed in further detail with respect to FIGS. 5 and 6.

The production changes that may result from the techniques may be modeled by creating a geologic model of the reservoir and using the geologic model to calculate the amounts of hydrocarbons produced. The geologic model may include open hole log data, cased hole log data, core data, recovery process well trajectories, 2D seismic data, 3D seismic data, or other remote surveying data, or any combinations thereof. For example, prior to the start of recovery operations, a geologic model can be created for the development area. Available open hole and cased hole log, core, 2D and 3D seismic data, and knowledge of the depositional environment setting can all be used in the construction the geologic model. The information generated by the geologic model may then be used in a reservoir simulation model to provide predictions of fluid flow, reservoir geometry, and the like.

The geologic model, reservoir model, and knowledge of surface access constraints can then be used to complete the layout of the spaced horizontal wells and surface pads. After the horizontal wells have been drilled, data collected during their drilling as well as data collected during the operation of the recovery process, such as cased hole logs including temperature logs, observation wells, additional time lapse seismic or other remote surveying data, can be used to update the geologic model, which may be used to predict the evolution of the depletion patterns as the recovery process matures. The depletion patterns within the reservoir will be influenced by well placement decisions, geological heterogeneity, well failures, and day to day operating decisions.

Following the operation of the thermal, thermal-solvent or solvent based recovery process for a suitable period of time, intervals of high hydrocarbon depletion will create a series of discrete connections between adjacent wells or well pairs, depending on the recovery process. Knowledge of these connections is gained through observances of interwell or interpattern communication of fluids, convergence of operating pressures, as well as via ongoing reservoir depletion monitoring with tools such as time lapse 3D seismic. This information may then be used to determine the appropriate time to convert from a cyclic production process to a continuous production process.

FIG. 5 is a plot 500 showing a simulation of the increase in total production that may be obtained using the present techniques. In the plot 500, the x-axis 502 represents the time since production was started, while the y-axis 504 represents the cumulative oil volume produced from the reservoir using basal planar gravity drainage (BPGD). The total production 506 that could be achieved using the present techniques 506 quickly reaches a maximum, allowing a much faster production of the resources. In contrast, the production 508 from a SAGD process may reach the same amounts, but only after many years.

FIG. 6 is a plot 600 showing a simulation of the increase in efficiency that can be obtained using the present techniques. The x-axis 602 represents the total amount of steam injected into the reservoir, while the y-axis represents the total volume of oil produced from the reservoir. As can be seen in the plot 600, if large volumes of steam are injected the SAGD and BPGD processes result in the same recovery levels. However, economic limits will dictate the actual volume of steam that can be practically injected. The benefit of the BPGD process, as indicated by comparing line 606 to a normal SAGD process, as indicated by line 608. For example, comparing the two cases at 200,000 m³ of steam injection volume, SAGD will have produced about 75,000 m³ of oil whereas the BPGD process will have produced about 110,000 m³ of oil.

An assumption inherent in a BPGD process is that a connection can be created between the injection well and the production well early in the recovery process. In the SAGD process a connection is typically established through a warm-up phase during which conductive heating is used to establish the connection. Because conductive heating is a relatively slow process the wells are spaced about 5 metres apart. It may also be useful to establish a distributed connection along the full length of the wells. If the connection or heated zone does not extend over the full length of the well then steam override may occur. For example, in areas within the reservoir, the steam chamber will rise to the top of the reservoir quickly and will then flow along the top of the reservoir to the producer. A similar situation often occurs when vertical wells are utilized for steamflooding. In order for a BPGD process to be most effective, the well can be configured such that the well lengths are much longer than the well spacing. Further, the wells can be completed with some form of flow control devices on the injector and producer such that the spacing of such devices is less than the well spacing, such as less than half than a distance between adjacent wells or less than a quarter of the distance between adjacent wells. The tighter the spacing of the perforations, the better the basal conformance. For example, the well lengths may be in the 300 to 1500 metres range, the well spacing in the 50 to 150 metres range and the flow control devices spaced every 10 to 50 metres along the well.

FIG. 7 is process flow diagram of a method 700 for a basal planar gravity drainage production of hydrocarbons. The method 700 begins at block 702 with the drilling of a first horizontal well at the base of the reservoir. The first horizontal well may be around 500 to 1500 metres long. The base of the reservoir, or target production zone, may be determined by a geological model, seismic imaging, or any number of techniques. The first horizontal well, which will be a production well during continuous operations, may be completed with LEP screen-type completions that are sized to allow distributed liquid in-flow along the length of the well. The total area of the perforations may be selected to limit the influx of vapour during continuous production.

At block 704, a second horizontal well is drilled parallel to the first horizontal well, and is typically of the same length. The second horizontal well may be laterally offset between about 50 and 200 metres from the first horizontal well. The second horizontal well may be drilled three or more metres above the completion depth of the first horizontal well. In a field having multiple horizontal wells, the depths of the horizontal wells may vary, depending on the base of the reservoir. However, neighbouring horizontal wells will generally have alternating depths. The second horizontal well, which will be an injection well during continuous operations, may be completed with limited-entry perforation (LEP) screen-type completions that provide for evenly distributed steam injection where the steam is injected in the vapour phase. Typically, the LEP's in the second horizontal well will have a larger open area than those in the first horizontal well when the mobilizing fluid is injected as predominantly a vapour, for example, as steam, and produced as a liquid.

At block 706, fluid communication may be established between the wells. This may be performed by any number of cyclic production processes. For example, as discussed with respect to FIG. 2, cyclic steaming of horizontal wells with LEP's completions can create uniform basal heating that establishes fluid communications between adjacent wells. After about two to three cycles of CSS, the heated features between wells may overlap, and the wells may be converted to steamflood.

In some types of reservoirs, a basal plane gravity-drainage layer may be established by injecting a fluid at rates that induce fracturing. As such, this connection process is particularly suited to reservoirs where the stress state favours horizontal fractures. Most commonly reservoirs that favour horizontal fractures are found at depths shallower than about 500 m. It may also be possible in some reservoirs to precondition the reservoir to favour horizontal fractures through pressurization. This may allow horizontal fractures to be generated at greater depths. For example, this may be performed by injecting water, steam, or solvents to raise the reservoir pressure.

In reservoirs where the stress state may not favour horizontal fractures, solvent fingering may offer an alternate mechanism for generating connections. Solvent fingering is a mechanism whereby a less viscous injected fluid invades a reservoir that is saturated with a more viscous fluid, and occurs when solvent is injected into heavy oil. It is known that solvent fingers will propagate towards regions of lower pressure. The connection can be generated by the cyclic injection and production of solvent into the first horizontal, or production, well in order to establish a finger network of high mobility. Solvent may then be injected into the second horizontal, or injection well, generating a second network of fingers while producing from the first horizontal well. The shortest pathways between the injection well and production well would be expected to dominate the flow paths and establish a basal communication path.

Once fluid communication is established between the first and second horizontal wells, at block 708, the second horizontal well may be used as an injection well, with a continuously injected stream of a mobilizing fluid. The injected mobilizing fluids could be steam, solvent, hot water, or mixtures thereof. At block 710, fluids may be continuously produced from the first horizontal, or production, well.

While the present techniques may be susceptible to various modifications and alternative forms, the embodiments discussed above have been shown only by way of example. However, it should again be understood that the techniques is not intended to be limited to the particular embodiments disclosed herein. Indeed, the present techniques include all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.

Embodiments

An embodiment of the present techniques provides a method for producing hydrocarbons from a reservoir. The method includes drilling a first horizontal well substantially proximate to a base of a reservoir and drilling a second horizontal well at a horizontal offset from the first horizontal well. Fluid communication is established between the first horizontal well and the second horizontal well through cyclic production processes. A mobilizing fluid is injected through the second horizontal well and fluids are produced from the first horizontal well.

The horizontal offset may be between about 50 and 200 meters. The second horizontal well may be about three meters, or more, shallower than the first well. Pressure on the reservoir may be equalized by conditioning.

The second horizontal well may be completed with limited entry perforations (LEPs) configured to evenly distribute a steam injection. The limited entry perforations (LEPs) can be spaced at distances less than half of a distance between the first well and the second well. The first horizontal well can be completed with limited entry perforations (LEPs) configured to provide a substantially even production of fluids. The limited entry perforations (LEPs) can be spaced at distances less than half of a distance between the first well and the second well.

Fluid communication can be established between the first horizontal well and the second horizontal well by creating solvent fingers using cyclic solvent injection and production. Further, fluid communication can be performed performed by cyclic steam stimulation, cyclic solvent stimulation, or both.

Injecting a mobilizing fluid can include steam injection, solvent injection, or a mixed injection. The pressure in the reservoir may be raised to create horizontal fractures.

Another embodiment provides a system for harvesting resources in a reservoir. The system includes a first horizontal well substantially proximate to the base of the reservoir and a second horizontal well at a horizontal offset from the first horizontal well, wherein the second horizontal well is vertically offset from the first horizontal well. A cyclic production system is configured to establish fluid communication between the wells. A continuous injection and production system is configured to inject a mobilizing fluid into the second horizontal well and produce a fluid from the first horizontal well.

A steam generation system can be configured to provide steam for injection. A separation system can be configured to separate a hydrocarbon stream from a produced fluid. A geologic model can be configured to locate the base of the reservoir.

Another embodiment provides a method for producing hydrocarbons. The method includes producing fluids from a number of production wells in a reservoir, wherein each of the production wells are located substantially proximate to the base of the reservoir. Mobilizing fluids are injected into the reservoir through a number of injection wells, wherein each of the plurality of injection wells is adjacent to one of the plurality of production wells. Further, each of the injection wells is laterally offset from each of the adjacent production wells, and each of the injection wells is drilled at a higher level than each of the adjacent production wells. A hydrocarbon stream is separated from the fluids produced from the plurality of production wells.

Each of the injection wells can be drilled at a shallower level than each of the adjacent production wells. The lateral offset may be between about 50 and 200 meters, and each of the injection wells may be at least about three meters higher than a neighboring production well. Each of the plurality of production wells can be completed with a limited entry perforation screen configured to reduce the entry of vapor into the production well. 

1. A method for harvesting resources in a reservoir, comprising: drilling a first horizontal well substantially proximate to a base of a reservoir; drilling a second horizontal well at a horizontal offset from the first horizontal well, establishing fluid communication between the first horizontal well and the second horizontal well through a cyclic production process; injecting a mobilizing fluid through the second horizontal well; and producing fluids from the first horizontal well.
 2. The method of claim 1, wherein the horizontal offset is between about 50 and 200 metres.
 3. The method of claim 1, wherein the second horizontal well is greater than about three metres shallower than the first well.
 4. The method of claim 1, comprising equalizing pressure on the reservoir by conditioning.
 5. The method of claim 1, comprising completing the second horizontal well with limited entry perforations (LEPs) configured to evenly distribute a steam injection.
 6. The method of claim 5, wherein the limited entry perforations (LEPs) are spaced at distances less than half of a distance between the first well and the second well.
 7. The method of claim 1, comprising completing the first horizontal well with limited entry perforations (LEPs) configured to provide a substantially even production of fluids.
 8. The method of claim 7, wherein the limited entry perforations (LEPs) are spaced at distances less than half of a distance between the first well and the second well.
 9. The method of claim 1, comprising establishing fluid communication between the first horizontal well and the second horizontal well by creating solvent fingers using cyclic solvent injection and production.
 10. The method of claim 1, wherein establishing fluid communication is performed by cyclic steam stimulation, cyclic solvent stimulation, or both.
 11. The method of claim 1, wherein injecting a mobilizing fluid comprises steam injection, solvent injection, or a mixed injection.
 12. The method of claim 1, comprising raising the pressure in the reservoir to create horizontal fractures.
 13. A system for harvesting resources in a reservoir, comprising: a first horizontal well substantially proximate to the base of the reservoir; a second horizontal well at a horizontal offset from the first horizontal well, wherein the second horizontal well is vertically offset from the first horizontal well; a cyclic production system configured to establish fluid communication between the wells; and a continuous injection and production system configured to inject a mobilizing fluid into the second horizontal well and produce a fluid from the first horizontal well.
 14. The system of claim 13, comprising a steam generation system configured to provide steam for injection.
 15. The system of claim 13, comprising a separation system configured to separate a hydrocarbon stream from a produced fluid.
 16. The system of claim 13, comprising a geologic model configured to locate the base of the reservoir.
 17. A method for producing hydrocarbons, comprising: producing fluids from a plurality of production wells in a reservoir, wherein each of the production wells are located substantially proximate to the base of the reservoir; injecting mobilizing fluids into the reservoir through a plurality of injection wells, wherein: each of the plurality of injection wells is adjacent to one of the plurality of production wells; each of the plurality of injection wells is laterally offset from each of the adjacent production wells; and fluid communication has been established between an injection well and an adjacent production well using a cyclic production process; and separating a hydrocarbon stream from the fluids produced from the plurality of production wells.
 18. The method of claim 17, wherein each of the plurality of injection wells is drilled at a shallower level than each of the adjacent production wells.
 19. The method of claim 17, wherein the lateral offset is between about 50 and 200 metres, and each of the plurality of injection wells is at least about three metres higher than a neighbouring production well.
 20. The method of claim 17, comprising completing each of the plurality of production wells with a limited entry perforation screen configured to reduce the entry of vapour into the production well. 